1. Field of the Invention
The invention relates to drill bits used for boring or penetrating the earth. In particular, the invention is a new fixed cutter drill bit with cutting elements arranged in a manner to actively cut the gauge portions of a borehole in the earth to facilitate directional drilling.
2. Description of the Related Art
Until relatively recently, a primary design goal for the designers of both fixed and rolling cutter earth boring drill bits was to design bits which would drill straight holes through the earth in spite of the tendency of the bit to follow along the dips and strikes of bedded rock formations in the earth. A great body of design knowledge accumulated over the years has taught these bit designers how to adjust the bit design parameters to accomplish straight hole drilling.
However, a division occurred early on in the body of straight hole drilling knowledge between fixed cutter drill bits and rolling cutter drill bits. Even though the broad concepts to accomplish straight hole drilling are common to both bit types, the specific bit design parameters are drastically different. Excellent discussions of straight hole and directional drilling for rolling cutter drill bits may be found in U.S. Pat. Nos. 5,372,210 and 4,231,438 both herein incorporated by reference for all they disclose.
By contrast, fixed cutter drill bit designs often provide quite different features than rolling cutter drill bits for straight hole drilling. For instance, rather than providing a relatively sharp corner to the gauge as described in the above rolling cutter bit Patents, fixed cutter drill bits tend to provide a long gauge section with a rounded transition to promote straight hole drilling.
Very recently, however, interest has been focused on making drill bits easy to steer while drilling the earth, a method known as directional drilling. In directional drilling, it is still necessary to make bits that do not wander from the desired path along the dips and strikes in the formation. However, the bits have the added constraint that they must be easy to steer, and predictably hold along a horizontal trajectory while drilling.
There are two common ways to steer a drill bit. The first and more common method may be called xe2x80x9cpointing the bitxe2x80x9d. This conventional approach to drilling a directional well uses a downhole motor that uses fluid flow to produce downhole rotation, independent of string rotation, and an angled bend for orientation of the tool face. This is usually accomplished by providing a bent section between the drill bit and a downhole motor such that the axis of the bit is not co-linear with the rest of the bottom hole assembly. To steer, the drill string and bottom hole assembly is rotated until the bit is pointed in the desired direction. The drill string is then prevented from rotation, while the downhole motor is activated to rotate the bit. This part of the xe2x80x9cpointing the bitxe2x80x9d method is known as the sliding mode because only the bit is rotating. The remainder of the drill string is caused to slide through the hole without rotation while the bit is drilling. In this mode, the bit will drill ahead, constantly building up the angle of the hole in the desired direction.
With the motor in sliding mode (drill string is stationary), torque and drag is generated by the bit which result in toolface fluctuations and reduced directional control. Transfer of weight to the bit can be irregular which will produce varying torque due to changes in the depth of cut, resulting in a reduced penetration rate. The lack of toolface control can result in severe doglegs and high tortuosity of the well. This may cause problems later on when it comes to casing the borehole, and during well completion. As directional complexity and length of horizontal sections increase, these problems become more significant.
In order to control how quickly the angle builds, the motor is periodically stopped and the entire assembly is rotated. A drill bit operated in this mode is forced by the bent sub to rotate in an orbiting motion and the bit tends to drill a hole larger than gauge diameter. Rotating in this manner also puts extreme loads on the gauge cutting elements of the bit, leading to premature wear.
Although this method of steering a bit has been extensively used, there are many problems. With conventional steerable assemblies using mud motors, directional changes are performed with the drill stationary and with a bend in the motor positioned to attain required tool face orientation. Upon drilling, the bit generates a reactive torque that proceeds to wind the string up. If the resultant reactive torque from the bit proves to be greater than the torque capability of the motor, the motor will stall. If this occurs, the assembly must be picked up off bottom and tool face orientation must be re-established. Torque fluctuation while sliding will also create changes in the orientation of the toolface and make steering difficult.
This problem has been addressed in the past by using rolling cutter drill bits or PDC fixed cutter bit designs with high backrake angles i.e. less aggressive bits. The compensation for increased tool face control is a loss in achievable penetration rates.
A newer approach which solves many of these limitations is a method known as xe2x80x9cpush the bitxe2x80x9d. In this method, a rotary steerable tool is able to make changes in inclination and azimuth with continuous rotation of the drill string. This leads to a cleaner, smoother hole,. and less drag, which is beneficial for drilling extended reach wells. A smoother transfer of weight to the bit will lead to increased penetration rates.
A tool commercially available for the xe2x80x9cpush the bitxe2x80x9d method typically consists of two main elements. The first element is a unit that contains mechanical components that can apply a lateral directional force (xe2x80x98side forcexe2x80x99) against the well bore. This is intended to push the bit in the opposite direction to the steering force imposed and can be used to make three-dimensional adjustments. The second element is a control unit housing the control electronics and sensors and may also contain measuring while drilling (MWD) and/or logging while drilling (LWD) sensors. This control unit is independent of external rotational speed. Programming and monitoring of the tool can be made at surface via the use of mud pulses. This communication with the tool can be made while continually drilling. One particular rotary steerable tool of this type is known as a side force rotary steerable (SFRS) tool and is described in U.S. Pat. Nos. 5.265,682; 5,553,679; 5,582,259; 5,603,385; 5,685,379; 5,706,905; 5,778,992; 5,803,185 all herein incorporated by reference for all they disclose.
Several functional qualities are required in a fixed cutter drill bit to properly operate with a SFRS tool.
A SFRS tool is commonly used in high inclination and horizontal wells and thus the drill bit should be of short length and possess the ability to move laterally. This allows the bit to make accurate and immediate responses to the directional changes initiated by the tool, resulting in improved dogleg potential.
The bit design should not induce significant vibration downhole, which could cause premature failure to the bit or tool. In general, high levels of lateral vibration (bit whirl) will lead to damage and eventual fatigue failure of the weakest part of the drill string. In the case of a SFRS system, damage can occur to the mechanical units that are used to actuate the directional moves. The sensitive electronic components in the control unit are also vulnerable to severe bit whirl.
Torsional vibration (stick-slip) is a major cause of bit and drill string failures. The use of a SFRS system, when compared to a conventional steerable motor is more likely to witness incidents of stick-slip due to the generally lower rotational speeds and the stiffness of the assembly. It has been observed that instances of stick-slip seem to correspond to changes in the strength of the rock being drilled.
From past experience, particularly in North Sea applications, the bit will be expected to drill through inter-bedded formations where hard stringers will be encountered. This type of formation is known to be the cause of cutter failure in PDC type fixed cutter drill bits, and is suspected to be the cause of torsional vibrations.
In the past, it had been assumed that increasing the anisotropic index of a bit was the primary requirement for fulfilling the above requirements for a fixed cutter drill bit to properly operate with a SFRS tool. The anisotropic index of a bit is defined as the ratio of axial drilling force to lateral drilling force to achieve a given penetration rate. A more detailed description of the anisotropic index may be found in a paper by Clegg, J. M., entitled xe2x80x9cAn analysis of the Field Performance of Antiwhirl PDC Bitsxe2x80x9d Society of Petroleum Engineers paper SPE 23868, presented at the 1992 IADC/SPE Drilling Conference, New Orleans, 18-20 February., 1992. The anisotropic index is also described in U.S. Pat. Nos. 5,456,141 and 5,608,162 both herein incorporated by reference for all they disclose.
Heretofore it was believed that the increase in the anisotropic index caused by modifying the bit profile was all that was necessary for use with the SFRS tool. The relative advantages in steerability induced by the changing the profile of a bit may be compared by calculating the anisotropic index for each design. This figure can then be used to determine the amount of force required to push the bit at a specific build rate. By comparison of the required steering forces of varying cutter profiles, bit designs may be ranked by their sensitivity to lateral. deviation. It has been found, however that maximizing the anisotropic index of a bit does not necessarily make it the best design for properly operating with a SFRS tool.
One type of conventional bit with a very high anisotropic index is known as a sidetrack bit. The common characteristics of sidetrack bits are their flat face profiles, very low gauge height to overall height ratios, and very ""sharp, aggressive gauge sections. Although these types of bits perform well for the specialized task of side tracking, they have proven to be too unstable for use with a SFRS tool. In fact these bits tend to have high, relatively unpredictable amounts of lateral vibrations, as well as experiencing severe stick-slip (torsional vibrations). When conventional approaches for mitigating these problems for PDC type bits, such as increasing the backrake of the cutters, are applied, the resulting anisotropic index also significantly drops.
Prior to the present invention, PDC type fixed cutter drill bits with a combination of high ratios of axial drilling force to lateral drilling force (high anisotropic indices) and low levels of both lateral and torsional vibrations, that are desirable for use with a SFRS tool were not available.
The present invention is a drag-type drill bit for use with a side force rotary steerable (SFRS) tool that provides a combination of a relative high ratio of axial drilling force to lateral drilling force while providing relatively low levels of both lateral and torsional vibrations.
This is accomplished by providing a new drag-type drill bit for drilling a borehole in the earth. The bit is designed to rotate about a central axis of rotation and has a bit body having a leading face, an end face, a gauge region, and a shank for connection to a drill string, a plurality of nozzles in the bit body for delivering drilling fluid to the end face, a plurality of blades upstanding from the leading face of the bit body and extending outwardly away from the central axis of rotation of the bit. Each blade terminates in a gauge pad which has a surface which faces a wall of the borehole. A first plurality of cutters are mounted on the blades at the end face of the bit body and a second plurality of cutters are mounted the gauge pads and arranged such that in operation, they cut the wall of the borehole. Each one of the second plurality of cutters has a backrake less than or equal to about 20 degrees. A plurality of non-cutting bearing element are mounted on the gauge pads in a trailing relationship relative to the rotation of the bit behind at least some of the second plurality of cutters. The surface of the gauge pad is relieved from the borehole by at least 3 mm.
It has been found that it is important to maintain the at least 3 mm of relief between the gauge pads and the borehole in order to provide space for drilling fluid to flow about the cutters provided thereon. The beneficial effect of the relief is reduced, however, when a relief greater than 7 mm is provided, due to fluid erosion. Therefore the optimal relief between the gauge pad and the borehole is between about 3 mm and about 7 mm.
It has also been found advantageous that each one of the first plurality of cutters have a backrake of between about 15 degrees and about 20 degrees.
It has also been found advantageous for drill bits made in accordance with the present invention that the portion of the first plurality of cutters located in the cone region of the bit preferably to have a backrake of about 15 degrees. In addition, it has been found advantageous that the portion of the first plurality of cutters located in the shoulder region of the bit preferably have backrakes of about 20 degrees.
The second plurality of cutters may be PDC type cutters having curvilinear cutting faces, preferably circular cutting faces.
It is also advantageous to provide a bottom hole assembly which includes a side force rotary steerable system (SFRS) along with the aforementioned drill bit.